No abstract

No abstract

TX 75083-3836 U.S.A., fax 01-972-952-9435. AbstractIn addition to geological and petrophysical data acquisition during the exploration stage, in-situ fluid analysis provides a wealth of information for the appraisal of new discoveries. A recently introduced wireline sampling tool incorporating a downhole fluid analyzer is capable of analyzing fluid composition in real time at downhole conditions, and of measuring the fluorescence spectra of crude oils. These new measurements provide valuable information necessary for the identification and validation of reservoir structures that define the distribution of fluids in the accumulation. The relevance of high quality fluid data in the early stages of the producing life of the reservoir is widely recognized. We present field results of the application of the new sampling tool in an exploration well, where a composition gradient was detected along a 30m liquid hydrocarbon column grading from a 45API crude on the top to a 33API crude on the bottom. During the sampling of the gas cap, retrograde dew formation was detected identifying the fluid and identifying valid sampling conditions. This new information was used to modify the sampling program. Fluid composition analysis relies on optical absorption methods and is currently capable of providing the mass fraction of three hydrocarbon molecular groups: C1, C2-5 and C6+, and CO2.We perform fluorescence spectroscopy by measuring light emission in the green and red ranges of the spectrum after excitation with blue light. Fluorescence in this range is related to the concentration of polycyclic aromatic hydrocarbons (PAH's) in the crude oil. Using the pump-out module to segregate different fluid phase enhances phase detection with fluorescence.

Reservoir fluids often show complex compositional behaviors in single columns in equilibrium due to combinations of gravity, capillary and chemical forces. Frequently non equilibrium or non stationary state conditions are also encountered, for instance due to thermal forces acting. Recognizing these behaviors downhole is a complex process that requires a greater number of data points, fluid samples and associated laboratory analysis. Pressure gradients with wireline formation testers are traditionally used to evaluate fluid density, fluid contacts, and layer connectivity in exploration settings. This information is today supplemented by downhole fluid analysis (DFA) measurements to reveal possible reservoir fluid heterogeneities. Although these fluid complexities have been largely recognized, conventional pressure-depth plot and pressure gradient analysis are still performed with traditional straight line regression schemes. This process may however be misleading as fluid compositional changes and compartmentalization give distortions in the pressure gradients, which lead to erroneous interpretations of fluid contacts or pressure seals. Hence the models imposed on the pressure data to calculate pressure gradients need to incorporate a rigorous mathematical approach to respect all data available, so as to follow an objective assessment of reserves and reservoir architectures. This paper presents a method to use combined repeated pressure and in-situ fluid measurements to provide a simple model of vertical fluid distributions, looks at the different regression schemes that can be imposed on pressure data to calculate fluid gradients with their associated uncertainties and concludes on an optimal fit approach. This data integration then allows making assessments and quality control of the different measurements and conclusions about the relevant reservoir heterogeneities. The method is illustrated with a published case study [1] from a North Sea appraisal well, where a large compositional gradient has been observed with in-situ fluid measurements. An equation of state is elaborated from a sample and its PVT experimental results, and a compositional gradient is parametized using the DFA observations at the different depths. A polynomial fit is then given to the distributed pressure measurements and the obtained fluid density variations are compared to the fluid model ones. Introduction Recently developed wireline technologies involving downhole fluid analysis measurements through optical spectroscopy, refractometry and fluorescence, have shown how to reveal non homogeneous fluid distributions in reservoirs [1], [2]. Light and near critical reservoir fluids often exhibit significant continuous variation of hydrocarbon components with depth. This has been illustrated in the literature [3], [4], [5]. With increased drilling in HPHT (high pressure, high temperature) and deep offshore settings, more and more fluids with complex phase behavior are met. Crossing the phase envelope of a hydrocarbon fluid mixture, although often unpredictable in the reservoir, is common: saturated oils are accompanied with a phase transition and a gas cap in the reservoir. Interestingly also, pressure and temperature ranges of 350–400 bars and 80–100C are close to critical temperature of mixtures of hydrocarbons in several settings. Near critical fluids are then encountered and their description and volumetric behavior is complex. When a critical transition exists in the reservoir, the fluid column then changes from a bubble point fluid to a dew point fluid without encountering a fluid meniscus or contact. Further anomalies may arise also because these reservoirs may possibly not be in thermodynamic equilibrium, but still undergoing for instance a flux from the source rock, where the lighest components, such as methane, tend to diffuse faster. This has been shown by Montel et al. [3]

Pressure-depth plots have been used for over thirty years to evaluate fluid density, fluid contacts, and pressure compartmentalization in formation tester pressure surveys. However in the Niger Delta region and other offshore deepwater environments, many reservoirs are multilayered and highly variable in terms of connectivity, permeability and fluid properties. Such complexity and reservoir heterogeneity means conventional pressure-depth plot and pressure gradient analysis of wireline pressure data is not easy, and identification of in-situ fluid type can be difficult. There is also mounting evidence for the presence of compositional gradients in the hydrocarbon columns of some reservoirs - this raises questions about the conventional approach to pressure gradient analysis and uncertainties in inferring fluid properties and contacts from pressure gradients. In this contribution using several field examples, we discuss and review formation pressure measurement techniques and data quality, and compare conventional and advanced methods of pressure gradient analysis and fluid contact determination. The interpretation techniques compared include traditional pressure-depth graphical methods, the excess-pressure method and statistical tests. Depth dependent fluid property variation from fluid gradients, PVT properties and EOS-models are compared and discussed. Guidelines are presented on how to interpret wireline pressure measurements in multilayered siliclastic reservoirs, perform connectivity and compositional gradient assessment. We describe how to improve on these interpretations by performing more advanced formation testing procedures; some of which are based upon new and emerging technology. Introduction Formation pressure profiles have long been used as important tools for determination of reservoir pressure, evaluation of fluid type from in-situ densities, identification of fluid contacts, and differential depletion, and inter-reservoir connectivity. Pressure profiles and fluid density gradients provide valuable information for reservoir evaluation and management, and input to aid decisions about well completion strategies and field production schedules. Modern wireline formation testers are equipped with quartz pressure gauges of high accuracy, resolution and repeatability. Theoretically, this higher resolution is sufficient for detection and evaluation of small fluid density changes and pressure variations within individual wells - this capability potentially leads to some new applications and interpretation techniques for formation pressure data. These new applications could include improved integration of pressure measurements and pressure gradient analysis with reservoir fluid and thermodynamic models. However such an approach requires good data quality control and data analysis, since pressure measurement problems, supercharging, wettability effects, and depth measurement errors can make it difficult to acquire representative pressure data and hence limit fluid gradient accuracy and reliability.